City of Glendale
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Rumors Regarding the City's Power Needs
Recently, comments were made at a Council meeting regarding Glendale Water & Power’s (GWP) Clean Energy RFP, contending that the City does not need 234MW of capacity, and that the City does not need to meet its identified contingency and planning reserve needs. The facts below address those contentions.
x While the RFP identifies a need of 235MW of capacity, Glendale doesn’t need anything close to 235MW of capacity.
✔ This is incorrect. The RFP identifies a need of 235MW, because Glendale needs 235 MW of capacity. To be exact, the Clean Energy RFP seeks 234 MW of capacity in order to ensure that Glendale can meet peak load and cover its contingency reserve obligation (N-1) and its planning reserve obligation (N-1-1). The Clean Energy RFP makes clear that Glendale will consider multiple projects to reach the 234 MW need, and the minimum size project that can be proposed is 1.0 MW.
Also, the 234 MW capacity figure does not take into account current load growth projections due to electrical vehicle usage. Analysis from the Department of Energy’s National Renewable Energy Laboratory (NREL) shows that electrical vehicle usage could drive a significant increase in load over the next three decades. See https://www.utilitydive.com/news/evs-could-drive-38-rise-in-us-electricity-demand-doe-lab-finds/527358/
Glendale’s need of 234 MW of capacity is shown in Figure 1, below. Glendale needs an additional 63 MW of capacity to meet peak load.[1] In addition, Glendale must maintain sufficient reserves to cover the loss of its single largest contingency (N-1) and its second largest contingency (N-1-1). Glendale’s current single largest contingency (N-1) is the loss of its share of the Pacific DC Intertie transmission line, which equates to the loss of 100 MWs generation. If Glendale repowers the Grayson Power Plant, its second largest single contingency will be loss of one of Grayson’s 71 MW units. Together, Glendale’s N-1 and N-1-1 equate to a total of 171 MWs. When this is combined with the 63 MW needed to meet peak load it equates to 234 MWs.
[1] The capacity numbers shown in Figure 1 reflect “best case scenario” capacities. During high heat conditions, the capacity is often lower.
Figure 1: Glendale’s Generation Needs
x Of the 234 MW, 65 MW is to meet peak load and the balance, about 170 MW, is for Planning Reserves.
✔ This is inaccurate. The 234 MW figure has three components, not two components. The first is the 63 MW needed to meet peak load. The second is the 100 MW of contingency reserves needed to cover Glendale’s N-1 condition. The third component is the 71 MW of planning reserves used to cover Glendale’s N-1-1 condition.
x There is no FERC or NERC requirement to maintain N-1-1 levels.
✔ As GWP has stated, Glendale does not have a direct obligation under the NERC Reliability Standards to maintain reserves. LADWP has that direct obligation. However, to the extent that the commenter is stating that there is no reliability requirement to maintain N-1-1 reserves, this is incorrect and reflects a basic misunderstanding about energy reserves, energy reserve planning and Good Utility Practice.
First, FERC and NERC do not promulgate separate reliability standards; FERC is the regulatory body that approves the NERC standards. So there would not, in any event, be separate FERC and NERC standards on reliability. There are regional standards, however, including in the WECC region in which Glendale is located. When it comes to reserves, the regional WECC standard for Balancing Authorities is more stringent than the national, NERC standard.
Second, the NERC Reliability Standards set the baseline requirements that power system operators must meet when utilizing reserves. The need to address the N-1-1 contingency comes from NERC Reliability Standard BAL002-WECC-2a part M1 and NERC Reliability Standard TPL-001-4, among others, as well as longstanding industry practice, referred to the industry as “Good Utility Practice.”
NERC Reliability Standard BAL002-WECC-2a part M1 is the regional standard in WECC (the region in which Glendale is located). It requires the Balancing Authority to maintain more stringent minimum reserves and requires restoration of contingency reserves (N-1) within 60 minutes following an event, rather than within the longer, 90 minute period in the national standard BAL-002.
If the N-1 is not restored within 60 minutes, then the utility must have the reserves needed to cover its next largest contingency (the N-1-1), in order to comply with BAL-002-WECC-2a part M1. Put another way, if the contingency event lasts longer than 60 minutes, then the N-1-1 contingency becomes the new, single largest contingency, and it has to be covered.
Similarly, NERC Reliability Standard TPL-001-4 (Transmission System Planning Performance Requirements) requires each Transmission Planner and Planning Coordinator in North America to perform the studies necessary to assess system performance under the following specified contingency conditions:
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Events resulting in the loss of a single element;
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Event(s) resulting in the loss of two or more (multiple) elements;
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Extreme event resulting in two or more multiple elements removed or cascading out of service.
In the context of the TPL standards, an entity meeting its N-1-1 contingency is referred to as meeting its Planning Reserve obligations. Planning Reserves (N-1-1 coverage) are separate and distinct from Contingency Reserves (N-1 coverage). Each set of reserves must be met separately.
x There is no obligation under the Balancing Authority Area Services Agreement (BAASA) with DWP to maintain N-1-1 reserve levels.
✔ Coverage of both the N-1 and N-1-1 conditions is a contractual obligation between LADWP and Glendale which predates the BAASA. In each of its transmission service agreements with LADWP, Glendale has agreed to be responsible for covering its own reserves (by self-provision or purchase) and to operate pursuant to “Good Utility Practice.”
Glendale operates, and has operated for decades, as a metered subsystem within the LADWP Balancing Authority Area (BAA). A metered subsystem is a geographically continuous system located within a Balancing Authority (usually a load serving entity) “which is responsible for balancing its own load and resources within its territory.”[2] In this role, Glendale has maintained reserves pursuant to its transmission service and related contracts, which contemplate it providing said reserves and operating pursuant to “Good Utility Practice.” These contracts predate the NERC Reliability Standards from the Energy Policy Act of 2005, by many decades. As such, Glendale has for decades maintained (by self-supply or purchase) reserves to cover both an N-1 and N-1-1 event.
Because Glendale has agreed to meet these obligations, if Glendale were to fail to do so, it could risk legal exposure for damages, contract penalties and pass through of any NERC penalties.
In addition, WECC would impose mitigation measures to prevent a future outage. These mitigation measures would require that the necessary amount of reserves are maintained, which would result in Glendale being responsible for self-supplying or purchasing these reserves.
[2] 153 FERC ¶61,024 at P 8 (2015).
x The decision to maintain enough reserves to meet the N-1-1 condition (170MW of reserves) is solely a policy decision. It should be decided on a prudential basis. Any discussion of external obligations is misleading.
✔ Glendale is obligated under the terms of its long-standing agreements to maintain reserves and operate and maintain its system in conformance with Good Utility Practice.
LADWP, the CAISO, other Balancing Authorities in California, the New York ISO, the ISO-North East, and virtually every other BA, ISO and RTO maintain reserves necessary to meet both the N-1 and N-1-1 contingencies and avoid outages. The utilities’ practice of maintaining reserves to meet N-1 and N-1-1 contingencies predates the NERC Reliability Standards, which were born out of the Energy Policy Act of 2005. Utilities maintain reserves to cover N-1 and N-1-1 because Good Utility Practice requires that a system operator be able to handle more than just the loss of one contingency. This is especially prudent for a utility like Glendale which has transmission constraints and cannot meet its load and reserve obligations using solely outside resources.
x Glendale is required to have no more reserves that what the BAASA requires, which is 80MW. The City has three options of obtaining that 80MW of reserves: (1) Glendale can self-supply, (2) It can purchase from a third party, which will be difficult given transmission challenges, or (3) it can “get them” from LADWP. LADWP is obligated to provide 80 MW reserves under the BAASA.
✔ This is wrong. Glendale must maintain reserves for both the N-1 and the N-1-1 scenarios. The BAASA only provides Glendale 80 MW of N-1 reserves for 60 minutes. The BAASA does not provide Glendale any N-1-1 reserves.
Under the BAASA, LADWP has agreed that it will sell Glendale 80 MW of spinning and supplemental reserves (i.e. N-1 reserves) for a period of no more than 60 minutes. In the BAASA, the Parties stipulated that 80 MW of reserves will be sufficient for GWP to meet its N-1 obligation (even though Glendale’s single largest contingency, the loss of the Pacific DC Intertie Line is a 100 MW contingency), but only on the condition that Glendale agrees to limit its transmission on the Pacific DC Intertie Line to 80 MW.[3] If Glendale wanted to use its full rights on the Pacific DC Intertie Line, it would need to either self-supply an additional 20 MW, or purchase an additional 20 MW from LADWP. Additionally, if the Pacific DC Intertie Line were to go down, triggering an N-1 event:
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Glendale only has the 80 MW of reserves to cover its N-1 contingency for one hour. At the end of the hour, if the Pacific DC intertie line is not back in service, Glendale is essentially on its own as LADWP will only continue to supply Glendale the 80 MW of energy after the hour if LADWP has excess generation available to do so. The rate for this energy is three times LADWP’s Tariff energy rate and GWP must return the energy it purchases back to LADWP at a future time.
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If the contingency lasts more than one hour, Glendale must also cover its second largest contingency (the N-1-1 contingency), because this is now becomes Glendale’s N-1 contingency. Because GWP’s N-1 contingency is the Pacific DC Intertie Line, which experiences frequent outages and de-rates, GWP is often in this position.
Under the BAASA, Glendale has purchased 80 MW of N-1 reserves from LADWP, for up to a 60 minute period. The BAASA allows Glendale to self-supply these reserves, but in order to do so, we would need to have reliable generation available to supply the reserves. The BAASA allows us to buy these reserves from someone else, but as the commenter notes, this is not a feasible option with our transmission constraints. Or we can buy it from LADWP. However, the purchases above the 80 MW have the limitations noted above and require transmission which may not be available. The BAASA does not provide N-1-1 reserves to Glendale.
In addition, buying reserves from LADWP is not cheap, and the ancillary service prices in the BAASA are not fixed. BAASA costs are based upon LADWP’s Tariff energy rates. The BAASA rates have increased significantly since the BAASA was signed and are certain to increase in the future. The commenter assumes that BAASA cost increases are limited to instances where “they [LADWP] have to build new capacity to support us.” This is not the case. LADWP has announced that it will enter the CAISO Energy Imbalance Market in the year or two, at which time the reserve capacity that LADWP current has set aside for Glendale will become much more valuable, and LADWP will have less and less capacity available for Glendale. In addition, the BAASA can be unilaterally canceled by LADWP at any time, on 18 months’ notice. Therefore, even assuming the BAASA fully covered Glendale’s reserve needs – and it does not –it is not a prudent strategy to rely exclusively on LADWP and the BAASA contract.
[3] Plus 6 MW of transmission losses.
x LADWP would have to build new capacity to support us.
✔ This is inaccurate. LADWP and Glendale do their own separate and distinct Integrated Resource Plans, which only address their individual needs. LADWP does not and cannot be expected to meet Glendale’s generation requirements as LADWP can only serve loads in its service territory.
x If Glendale has 80 MW of reserves and an N-1-1 event occurs, LADWP will be obligated to cover us.
✔ This is false. LADWP has no obligation to cover Glendale’s N-1-1 scenario. Additionally, LADWP will only supply Glendale energy to cover an N-1 scenario after 60 minutes, if LADWP has the energy available.
If an N-1-1 event takes place, this means that Glendale is in a situation where it has lost its two largest energy resources: (1) the Pacific DC Intertie Line has gone down (the N-1 contingency) and (2) Glendale has lost a unit at the power plant (the N-1-1 contingency). If this were to occur, for the first 60 minutes, LADWP would provide Glendale with 80 MW of energy to cover the N-1 contingency (loss of the Pacific DC Intertie), under the BAASA. The BAASA does not contemplate LADWP covering Glendale for the N-1-1 contingency (loss of the 71 MW unit). This means that Glendale would be 71 MW short. At the end of the 60 minute period, if the resources are not restored, Glendale would have a shortage of 151 MW (80 MW of lost import capability on the Pacific DC Intertie Line, and 71 MW loss of generation from the unit). Glendale would be required to scramble to find generation to cover this 151 MW loss. Due to transmission constraints, it is likely that it would not be able to cover even part, let alone all, of this loss. This would result in rolling blackouts to Glendale customers.
This concern about not being able to find sufficient generation is exacerbated by the fact that LADWP has a large ownership share of the Pacific DC Intertie line. Therefore, if the N-1 contingency occurs (i.e., the Pacific DC Intertie line goes down), the capacity shortage will also affect LADWP. With the loss of the Pacific DC Intertie, LADWP will be scrambling to meet the needs of its own residents and may not have excess energy available to sell or the excess transmission capacity available to deliver the energy to Glendale. Also, if an N-1 occurs during one of the peak load months, the entire region will be short of generation, which will make it difficult for Glendale to purchase energy from third-parties. This is why “Good Utility Practice” dictates that Glendale have sufficient local generation reserves to respond to these situations. Having blackouts is not a planning solution and cannot be a part of Glendale’s Integrate Resource Plan.
x LADWP cannot force us into rolling blackouts unless they themselves are implementing blackouts in their own service territory.
✔ False. LADWP has no obligation to prevent us from entering into rolling blackouts and no obligation to provide us with energy and capacity. The BAASA provides that, in the event of an emergency, a party must render all available emergency assistance to the other party as requested. However, if there is no generation available or if there is no transmission available to deliver electricity, Glendale will be left to fend for itself.
x What’s the probability Glendale we’ll have N-1-1 events? And what’s the probability that they will occur when loads are at their historical peak? How long do we expect these N-1-1 events to last?
✔ The Pacific DC Intertie, Glendale’s current N-1 contingency, experiences frequent de-rates or outages, which often last for more than 60 minutes. In fact, they can last for several hours, days, weeks, or even months. Below in Figure 2 is a graph that reflects the percentage of times such de-rates or outages have occurred on the Pacific DC Intertie over the past 10 years, during the highest load months of May through October:
Figure 2: Pacific DC Intertie Outages
The Pacific DC Intertie experiences a high frequency of outage events, which can last for significant durations. If Glendale does not carry reserves to cover its N-1-1 contingency, even though it is aware of the frequency at which it experiences a de-rate or loss of the Pacific DC Intertie –its N-1 contingency -- Glendale would spend significant periods of the year taking the risk of an N-1-1 event that it is not prepared to cover.
x What would Glendale pay LADWP to cover us during the hours that we are short?
✔ The comment incorrectly assumes we can pay LADWP to cover a shortage. The point is that LADWP has no obligation to cover us when we are short, except for the 80 MW that LADWP has agreed to provide under the BAASA, and only if the BAASA is not terminated. Glendale’s failure to follow Good Utility Practice and maintain reserves in accordance with its contractual commitments is not LADWP’s problem to solve. In addition, even assuming LADWP can and would provide power after the first 60 minutes, the rate for this energy is three times LADWP’s Tariff energy rate and GWP must return the energy it purchases back to LADWP at a future time.
x How does the cost of utilizing reserves from LADWP compare to the cost of building generation capacity?
✔ A cost-benefit comparison that is limited to comparing the cost of purchasing 80 MW of contingency reserves from LADWP to the cost of constructing Grayson is overly simplistic --- especially if that analysis is based upon the false premise that Glendale can buy all of the reserves it needs from LADWP, or that 80 MW is all the reserves that Glendale needs.
Below is load profile information for Glendale for the years 2015-2017.
Based upon the load profile data, Glendale’s energy demand was over 187 MW on an average of 92 days per year and an average of 673 hours per year. The 187 MW represents the only resources that would be available to Glendale if the Pacific DC Intertie transmission line goes down, once the aging Grayson units other than Unit 9 are no longer available. In this situation, the remaining resources available to Glendale are:
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48MW – Grayson Unit 9
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39MW – GWP’s share of the Magnolia Power Plant; and
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100MW – GWP’s share of Southwest Area Transmission
TOTAL: 187 MW
During these times GWP would not be able to meet load given that all local generation and all transmission would be fully utilized. It would also be GWP’s responsibility to ensure that there would be sufficient reserves to cover contingencies or would be forced to shed load further.
Approximate Total Cost for Each of the Generation Configurations:
Below are estimated costs of the proposed repowering options as presented to City Council on April 10, 2018. The below cost estimates are cost estimates as of April 10, 2018; costs are subject to change.
